Method of treating a fractured well

ABSTRACT

This invention relates to a method of treating a tight gas well that has been fractured with a gel solution to increase the production of hydrocarbons. The gel solutions used for fracturing typically include an aqueous portion and a polymer material. Generally, the first step of the method is to apply a soak solution to the fractured formation to mix with the aqueous portion of the gel solution to increase the volatility of the aqueous portion. The next step is to apply a dry gas treatment to the tight gas well to remove the aqueous portion of the gel solution after the volatility has been increased.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

This invention was made with the government support under contract no.DE-AC26-07NT42677 awarded by Department of Energy.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to a method for treating a tight gas well.Generally, the method includes the step of treating the tight gas wellwith a soaker solution then treating the tight gas well with a dry gas.

2. Description of the Related Art

Polymeric gels are widely used in hydraulic fracturing operations toproduce hydrocarbons (natural gas and/or oil) from tight formations. Therecovery of injected gel is often poor and large quantities are leftbehind, which can cause a loss in gas or oil productivity due to areduction in the fracture conductivity.

Accordingly, there is a need for a treatment method of tight gas wellswhereby larger quantities of the injected gel are recovered, thusincreasing the fracture conductivity and production of hydrocarbons fromtight formations.

SUMMARY OF THE INVENTION

The invention disclosed herein is directed to a method of treating anoil or gas well that has been fractured with an aqueous gel solution toincrease the flow of hydrocarbons. The aqueous gel solution has anaqueous portion and a polymer material portion. The method includescontacting a fractured formation with a soak solution. The soak solutionmixes with the aqueous portion of the aqueous gel solution to increasethe volatility of the aqueous portion of the aqueous gel solution. Thesoak solution also removes, due to thermodynamic phase behavior, theaqueous portion from the gel solution. After the soak solution isapplied, a dry gas treatment is applied to the well to evaporate theaqueous portion of the aqueous gel solution and reduce gel saturation inthe fractured formation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a front elevation view of a wellbore and a fracturedformation.

FIG. 2 is a close up, front elevation view of the wellbore and thefractured formation.

FIG. 3 is a graph view showing inlet pressure vs. time vs. flowrate.

FIG. 4 is a graph view showing gas relative permeability vs. time insand pack during displacement at flow initiation pressure of 80 psia.

FIG. 5 is a graph view showing gas relative permeability vs. time insand pack during dry gas treatment after displacement at a pressure dropof 10 psi.

FIG. 6 is a graph view showing gas relative permeability vs. time infracture pack during displacement at flow initiation pressure of 80psia.

FIG. 7 is a graph view showing gas relative permeability vs. time infracture pack during dry gas treatment after displacement at a pressuredrop of 10 psi.

FIG. 8 is a graph view showing gas relative permeability vs. time infracture pack affected by solvent treatment at a pressure drop of 10psi.

FIG. 9 is a graph view showing gas relative permeability vs. time infracture pack during dry gas injection after solvent treatment/soak.

DETAILED DESCRIPTION OF THE INVENTION

The present invention relates to a method of treating oil and/or gaswells to increase the production of hydrocarbons (oil and gas) fromtight formations 10. Referring now to the drawings and more particularlyto FIGS. 1 and 2, shown therein is a wellbore 12 drilled down into thetight formation 10. Inserted into the wellbore 12 is a casing 14 held inplace in the wellbore by cement 16. Furthermore, in FIG. 1 the tightformation 10, the casing 14 and the cement 16 have been perforated andfractured to generate multiple fractures 18 in the tight formation 10.The fractures 18 are typically made with an aqueous gel solution 20 thatincludes polymer material 22, proppants 24, such as sand. The proppants24 are included in the aqueous gel solution 20 to prop open thefractures 18 of the formation 10.

Once the formation 10 has been fractured with the aqueous gel solution20 and the proppants 24 have been placed in the fractures 18 to keep thefractures 18 open to facilitate the recovery of hycrocarbons from theformation 10, a portion of the gel solution 20 remains in the fractures18 retarding the recovery of hydrocarbons. This is due to the polymermaterials 22 of the aqueous gel solution 20 accumulating at the fracturesurfaces, due to a phenomena called “leak-ff,” which increases the gelconcentration of the gel solution 20 in the fractures. The gel solution20 left in the fractures can be up to ninety percent (90%) water.

Saturation, S_(gel), of the gel solution 20 is the fraction of the porespace of the fractures filled by the gel 20. This is represented by theequation S_(gel)=V_(gel)/V_(pore) and V_(gel)=V_(polymer)+V_(water),wherein V_(gel) is the volume of the gel 20, V_(pore) is i the volume ofthe pore space of the fractures, V_(polymer) is the volume of thepolymer material 22 in the gel solution 20 and V_(water) is the volumeof the water portion of the aqueous gel solution 20.

The gas permeability, thus hydrocarbon production, after the applicationof the method disclosed herein is an improvement of the gas permeabilityof the fractures 14 prior to the treatment method disclosed herein. Thetreatment method disclosed herein increases the gas permeability of thefractures 14 in an amount that is greater than about 5%.

The method disclosed herein can be used when connate brine is present inthe formation 10. The method can also be used when condensate forms andis present in the formation 10 or well. Further, the method can be usedin formations that are sensitive to water, such as swelling clayformations.

In one embodiment of the present invention, the fractured formation 10is treated with a soak solution that is miscible with the aqueousportion of the gel solution 20. The soak solution also thermodynamicallyinteracts with the aqueous portion of the gel solution 20. The soaksolution then mixes with the aqueous portion of the gel solution 20 toproduce a more volatile gel solution in the fractured formation 10, thusincreasing the evaporation rate of the resulting gel solution. The soaksolution also causes gel shrinkage due to removal of the aqueous portionfrom the gel solution, during the mixing process, thereby reducing thebulk volume of the gel solution. The soak solution can be any volatilesolvent that is miscible with the aqueous portion of the gel solution20. In one embodiment, the soak solution can include any alcoholcomprising at least one carbon atom. In another more specificembodiment, the soak solution can be any alcohol comprising one, two orthree carbon atoms. In one embodiment, alcohols that are environmentallyless hazardous than mono carbon atoms (methanol) can be used. An exampleof a soak solution includes, but is not limited to, a solutioncontaining isopropyl alcohol (IPA).

The soak solution can be applied at any pressure and flow rate such thatsoak solution contacts substantially all of the gel solution 20 thatremains in the fractured formation 10. In one embodiment of the presentinvention, the soak solution is applied to the fractured formation 10 ata pressure that is lower than the fracture pressure of the formation sothat no new fractures are created in the formation. Further, the soaksolution can be applied with our without various additives. Examples ofadditives include, but are not limited to, enzymes that can break up thepolymeric portion of the gel solution 20.

In another embodiment of the present invention, the soak solution isprovided to the fractured formation 10 and shut in the well a specifiedamount of time to allow proper mixing with the aqueous portion of thegel solution 20. The amount of time the soak solution is shut in dependson various factors at each wellsite where this treatment method is beingimplemented.

Once the fractures 14 and the fractured formation 10 has been contactedwith the soak solution, the resulting volatile gel solution (the mixtureof the aqueous portion of the gel solution 20 and the soak solution) isremoved from the fractures 14 and fractured formation. In one embodimentof the present invention, the resulting volatile gel solution isdisplaced by gas flow back or pumped out of the formation. In anotherembodiment of the present invention, the resulting volatile gel solutionis evaporated by the gaseous hydrocarbons being recovered from thefractured formation 10. In the event that any of the soak solution isrecovered from the formation, the spent or used soak solution can berecycled for later treatments.

In another embodiment of the present invention, the resulting volatilegel solution is subject to a dry gas treatment to remove the aqueousportion of the resulting volatile gel solution. The aqueous portion ofthe volatile gel solution is the resulting combination of the soaksolution and the aqueous portion of the gel solution 20. The addition ofthe soak solution makes the aqueous portion of the volatile gel solutionmuch more volatile (increased evaporation ability) than the aqueousportion of the gel solution 20. A volatile aqueous fluid is defined as afluid whose vapor pressure is greater than that of the polymer which isdissolved in the gel solution. This increased volatility of the aqueousportion of the volatile gel solution allows the dry gas treatment toevaporate substantially all of the aqueous portion of the volatile gelsolution. The evaporation of substantially all of the aqueous portion ofthe volatile gel solution from the dry gas treatment dries the fractures18, the polymer material 22 and the proppants 24 delivered to thefractures 18 by the aqueous gel solution 20 lowers the V_(water) in thefractures 18. Lowering the V_(water) in the fractures 18 also lowers theV_(gel). The lower V_(gel) results in the S_(gel) being lower. Theproduction of hydrocarbons from the fractured formation 10 increases asthe S_(gel) is lowered. It should be understood and appreciated that thedry gas treatment described herein can be applied to gel solutionswherein the polymer material is mixed with a non-aqueous fluid to formthe gel solution.

Once the volatile gel solution is dried, the polymeric portion 22shrinks and does not swell again. The effects of this treatment methodare irreversible unless fresh fracturing fluid is applied to theformation 10. In a further embodiment of the present invention, thetreatment is applicable to specific polymer materials 22 used in thefracturing gel solution 20. Examples of these polymer materials 22include, but are not limited to, guar gum polymer, guar gum crosslinkedwith metal atoms (such as Boron) and non-crosslinked naturally occurringguar based polymers. The treatment method disclosed herein is applicableat all concentrations of polymer material 22 in the gel solution 20. Ina further embodiment of the present invention, the drying gas treatmentcan be applied to non-aqueous volatile gel solutions comprising ofpolymer materials or polymer like materials.

The gas used in the dry gas treatment can be any gas capable ofefficiently evaporating the aqueous portion of the volatile gelsolution. Examples of dry gas that can be used in accordance with thepresent invention include, but are not limited to, any single carbonatom gas (e.g. carbon dioxide or methane), air, nitrogen, monoatomicgases, diatomic gases, subcritical drying fluids, supercritical dryingfluids, and combinations thereof (i.e. nitrogen enriched air). In afurther embodiment of the present invention, the dry gas can be a fluegas, exhaust gas or any gases resulting from combustion. The dry gas canalso have particulates removed therefrom via any manner known in theart. In another embodiment of the present invention the dry gas can beheated prior to injection into the well to increase the rate ofevaporation of the aqueous portion of the volatile gel solution. Theinjected gas can also be a dry (free from aqueous component)supercritical fluid or liquid under reservoir conditions of temperatureand pressure.

Experimental Method Sandback Preparation

A metal shell is created by wrapping aluminum shim stock around a solidcylinder. The diameter and length of metal cylinder is 1.0 inch and 3.0inches, respectively. The metal shell is then closed at one end with asand screen supported by a perforated end piece. The sand screen helpsto retain and prevent the sand from flowing along with the injectedfluids during experiment. The metal shell is then completely filled with16/40 (0.422-1.20 mm) mesh size sand and packed by continuous vibration.Subsequently the shell is closed with another end piece lined with asand screen and the entire assembly is securely fastened by usingadhesive tape.

Fracture-Pack Preparation

In order to create a fracture-pack, tight gas sandstone rock of 2.2 inchlong and 1.0 inch diameter is cut longitudinally to create equally sizedrock halves. A portion of the face of the rock is further removed toreduce the thickness of the rock half. The two halves are then assembledin the metal shell, prepared using procedure described in the previoussection for sandpacks. The space between the two halves is then filledwith sand of 16/40 (0.422-1.20 mm) mesh size completely and packed. Thewidth of this fracture-pack is approximately 3.8 mm.

Dry Gas Treatment

Dry gas treatment method is used to improve gas flowrate recovery. Drysandpack/fracture-pack is first subjected to invasion by gel fracturingliquid, the preparation of which is described herein. The invaded gel isthen subjected to wet gas flow-back. This step mimics the gas flow-backfrom the well subsequent to fracturing operation. The clean-up processduring this flow-back is mainly due to viscous displacement. Thedisplacement process ends when no more gel is visually observed at theoutlet end. When dry gas is injected, the water content of the gel ismainly removed by evaporation.

Solvent Treatment

Solvent treatment is used to improve gas flowrate recovery from geldamaged fracture-pack. Fracture-pack is initially subjected tofracturing fluid invasion followed by wet gas flow-back which displacesthe trapped gel. Two different solvent treatment methods are followed toimprove gas flowrate recovery from the fracture-pack. First is a solventflow treatment immediately following the gas flow-back and geldisplacement. Second is a solvent soak treatment in combination with drygas treatment after the gas flow-back.

Fluids Used

A borate cross-linked guar polymer is used as the fracture fluid. Thegel is prepared by slowly adding 3.0 grams of WG-35 Guar Polymer(obtained from Halliburton) to 1 liter of water and stirring at moderatespeed for 30 mins. Finally, 1.75 ml BC-140 cross-linker (obtained fromHalliburton) is added to the solution, making the solution crosslinkimmediately.

Dry air is used to evaporate the water content of the gel.Laboratory-grade isopropyl alcohol of 99.8% purity is used inexperiments performed for evaluating the effect of solvents. Airsaturated with water is used to displace the gel in thesandpack/fracture-pack. Wet gas helps minimize the evaporation effectduring displacement.

Experimental Procedure

The sandpack is placed inside a Hassler type triaxial core holder and aconfining pressure of 1000 psia is applied using compressed nitrogen.The tri-axial confinement prevents the sand from flowing under bothaxial and radial pressure. The sandpack is evacuated and fracturing gelis flowed through the sandpack at 10 cc/min for a time of 10 minutes. Agravimetric analysis is made to obtain the initial weight gained by thesandpack after injection. The gravimetric analysis is performed afterthe core is taken out of the core holder.

A certain inlet pressure is necessary to initiate gas flow through thesandpack which is completely saturated with fracturing gel. Thispressure may also be termed as the flow initiation pressure. A previousstudy shows that the flow initiation pressure is governed by theviscosity of the fracturing liquid and the permeability of the sandpack.In this study, the flow initiation pressure for the sandpack isdetermined by conducting an experimental sensitivity study withincreasing pressure drops upwards from atmospheric pressure. The resultsshow that the gas flow in sandpack is initiated after an inlet pressureof 80 psia is achieved (FIG. 3)

After gravimetric analysis, the sandpack is placed back in the coreholder to conduct gas displacement process and is subjected to the sameconfining pressure as before. Compressed instrument air, humidified bypassing through a column of water, is injected into the sandpack at aninlet pressure of 80 psia with atmospheric pressure at the outlet. Thisstep mimics the flowback from a gas well after a fracturing processusing gel. The displaced gel, from the sandpack, is collected at theoutlet. The gas injection is continued until no more gel is collected atthe outlet end. A gravimetric analysis of the displaced liquid isconducted to determine the gel saturation in the sandpack at the end ofdisplacement. Data acquisition system (National Instruments cFP-1804with LabView) connected to a work-station is used to continuously recordflowrates measured using a digital mass flow meter (Aalborg GFM17).

Subsequent to the displacement step, residual gel saturation is achievedin the sandpack, and no more gel can be removed. This condition issimilar to that observed in the field where there is no more fracturinggel recovery after a certain time during well flow-back. The gasflowrates achieved after the displacement step is low (3-5%) due to thelow relative permeability of gas. The wet gas flow-back is similar tothe field condition, where the gas produced is generally completelyhumidified due to contact with reservoir brine.

Dry gas is injected into the sandpack at 25 psia inlet pressure,subsequently, to initiate the evaporation process and to reduce thewater content of the trapped gel. The gas flowrates at the inlet end arecontinuously monitored using a mass flowmeter which is connected to theNational Instruments data acquisition system. The dry gas injectionprocess is complete when all the gel is completely dried and no moreimprovement in gas flowrate is observed. The dry gas treatment processon fracture-pack is performed using the same procedure as that ofsandpack.

Solvent treatment is applied either prior to the dry gas injection orsubsequently. In this study, Isopropyl Alcohol is used as a solvent.Approximately 15 pore volumes (80 mL) of solvent are flowed through thefracture-pack after the end of displacement. A soak period of 3 hours isprovided to enable better dissolution of the gel before dry gastreatment.

Results and Discussion Gel Clean-Up by Dry Gas Treatment in Sandpacks

When dry gas is injected, the water content of gel is gradually removeddue to the partitioning of water between gas and gel phase. Water isevaporated at greater rates near the inlet end due to the lack of waterin the injected gas. The gas becomes saturated with water on contactwith the gel phase as the mass transfer rates are expected to besufficiently fast to establish complete phase equilibrium across theentire pore space. The drying rate of gel in the sandpack thereforedepends mainly on the gas convection rates and to some extent on theexpansion driven drying. Viscous fingering, whose effects are discussedin a later section, however, can introduce complexities and thus cause adeviation from the above drying process.

When wet gas is flowed through the sandpack, to mimic gas well flow-backafter a hydraulic fracturing treatment, only a portion of the gel isdisplaced and hence the flowrate of gas recovers only to a small extent.FIG. 4 shows the recovery of gas flowrate during displacement of gelfrom a sandpack. The gas flowrate is essentially zero at the beginningof the displacement and for up to an hour. This is because the gelsaturation is 100% initially and the displacement of the gel is slow dueto the high viscosity of the gel. At the end of displacement, when nomore gel is observed at the outlet end, a gravimetric analysis isperformed to determine the residual gel saturation. It is observed thatabout 80% of the initial gel is still trapped in the sandpack at the endof displacement.

Subsequent to the gel removal by displacement, dry gas is injected toevaporate or desiccate the trapped gel. FIG. 5 shows the improvement ofgas relative permeability during the evaporation process. The effectivegas relative permeability increases gradually from a value of ˜0.01,initially, to approximately 0.29 at the end of evaporation process. Thegas relative permeability at early times during the dry gas injection islower than that at the end of displacement. This is due to the fact thatthe inlet pressure during the displacement experiment is 80 psia whilethat in the case of the evaporation experiment is 25 psia. Due to theevaporation process, the sandpack is completely dry after about 20hours. A gravimetric analysis confirms that the weight of gel insandpack after the dry gas injection is close to zero.

The gas flowrate at the end of the dry gas treatment is much higher thanthat at the end of displacement by gas flow-back. Thus the viscousdisplacement process alone leads to a poor recovery as compared to thedry gas treatment process. The gas relative permeability does not,however, recover beyond 29% even if the sandpack is completely dry. Thisis probably so because the evaporated polymer organizes itself in thepore space in such a way that the pore throats are plugged with thedeposited polymer which reduces the overall permeability of thesandpack. Gel Clean-up in Fracture-pack

When dry gas is injected into a fracture-pack, the evaporation processtakes place in a similar way to that of the evaporation by dry gas in asandpack. FIG. 6 shows the gas relative permeability recovery with timeduring displacement by gas flow-back in a fracture-pack. The gasflowrate recovers to about 5% of the original gas flowrate at the end ofdisplacement while approximately 70% of the gel still remains trapped inthe fracture-pack.

FIG. 7 shows the improvement in gas relative permeability when thefracture-pack is further subjected to dry gas treatment. The effectivegas relative permeability reaches 32% before the rates achieve aplateau. Thus the dry gas treatment is effective in reducing the liquidgel saturation while improving gas recovery. It should be noted that thefracture pack was taken out of the core holder after displacement. Thefigure shows the flowrate evolution after the fracture pack was replacedto conduct the evaporation experiment. The early times show a muchsmaller effective gas relative permeability compared to that at the endof displacement. This could be mainly due to the lower pressure drop (10psi) during the evaporation period as compared to the displacement (65psi) period.

Effect of Solvent Treatment With No Soak

Subsequent to displacement by gas flow-back, 15 pore volumes ofisopropyl alcohol are injected into the fracture to treat the residualgel. The fracture-pack is then immediately subjected to wet gasflow-back. FIG. 8 shows the improvement of the effective gas relativepermeability with time during gas flow-back. The improvement is comparedwith a case when the gas flow-back is continued without any solventtreatment. The trends readily show that when the residual gel is treatedwith alcohol the rate of improvement and the ultimate gas relativepermeability are higher. When alcohol treatment is used, the improvementof gas relative permeability in the first 20 hours is significant.Subsequently the improvement is gradual. The most likely cause of thisvariation is that the alcohol is more volatile and is easily evaporatedduring wet gas flow back as the wet gas contains no alcoholconcentration initially. Subsequently the residual gel continues toevaporate due to compressibility driven drying (Mahadevan et al. 2006),which is considerably slower. When there is no alcohol treatment, onlycompressibility driven drying takes place and improvement due to gelsaturation reduction is much more gradual.

The ultimate gas flowrate achieved after the alcohol treatment, with nosoak period, is 11% of the original undamaged rate, which is lower thanthat achieved with a dry gas treatment (34%). While multiple treatmentsof alcohol may be able to increase the end point gas relativepermeability or improve the ultimate gas flowrate achievable, the use ofalcohol alone is not as effective as a dry gas treatment.

Solvent Soak/Dry Gas Combination Treatment

When both dry gas and solvent treatment are used, the resulting clean-upand improvement in the gas flowrate is expected to be greater. Twodifferent treatment processes are considered in this study. In the firstcase dry gas treatment is conducted after an alcohol injection and soakperiod. In the second case dry gas treatment is followed by an alcoholtreatment.

Approximately 15 pore volumes of alcohol are injected into thefracture-pack after displacement and allowed to remain in thefracture-pack for approximately 3 hours to allow enough time for the gelto dissolve in alcohol. Subsequently dry gas is injected to completelyevaporate the alcohol and water trapped in the fracture-pack. Theimprovement in relative permeability during dry gas treatment is shownin FIG. 9. The figure also shows the improvement during a similar drygas injection without any alcohol treatment. The trends observed in thefigure clearly show a greater and faster improvement in the gas flowratein the case of alcohol treated fracture-pack as compared to that whenthere is no alcohol treatment. When treated with alcohol it takes lessthan an hour to achieve 15% of the undamaged gas flowrate compared to6.5 hours when not treated with alcohol. The ultimate gas effectiverelative permeability achieved is also high at 43%. It is possible thatthe higher volatility of alcohol combined with the phase behavior of gelcauses faster and greater recovery of gas rates.

In order to investigate the effect of addition of isopropyl alcohol(IPA) to gel, we performed an experiment ex-situ of the poroussandpack/fracture-pack. The experiment was timed to evaluate the gel'swater content when it is simply exposed to IPA. 10 grams of the gel wasimmersed and soaked in 100 ml of IPA for 3 hours which is an identicalsoak time compared to the alcohol treatment experiment on the sandpack.Visual observation of the gel immersed in the alcohol showed that thegel shrank and only a skeleton structure of a white colored substance(most likely the polymer and the cross-linker that were added to createthe gel) remained along with some entrapped water. The entire mixturewas filtered using a type 1 Whatman filter paper in a Buchner funnel.The residue exactly corresponded to the weight of polymer andcross-linker used in making the gel. Thus the IPA addition results incomplete removal of water from the gel matrix which perhaps representsthe ultimate equilibrium phase behavior of the gel alcohol system. Thereduction of gel size/weight due to removal of water content can lead toreduction of gel saturation and hence allow greater gas flow.

When dry gas treatment alone is used the ultimate gas rate is a maximumof 34% of the original undamaged fracture-pack. This is evidently lowerthan that of the case when alcohol treatment/soak precedes the dry gasinjection.

Injection of alcohol after a dry gas treatment, when the residual gel iscompletely dried, does not produce any significant impact on therecovered flowrate. This may be due to the non-dissolution of driedpolymer gel by the alcohol. It is here that additives mixed with thesoak solution can provide a break-up of the polymer thus increasing therecovery rate even higher.

Discussion on Gel Drying

Drying of liquids from porous media due to gas flow depends on thedistribution of the liquid within the medium. When the viscosity of theliquid is small capillary effects can redistribute the volatile liquidand enhance drying rate. However, in the gels, the viscosity isgenerally high and hence the gels are not mobile. Thus gel is poorlydistributed within a porous medium and is also affected by viscousfingering. The drying rate of gel, in the presence of complex viscousfingering and other mass transfer limitations is not well understood.This area is a candidate for future investigations as such compositionaleffects in the presence of unfavorable mobility displacements has widerapplications than considered in this study.

From the above description, it is clear that the present invention iswell adapted to carry out the objectives and to attain the advantagesmentioned herein as well as those inherent in the invention. Whilepresently preferred embodiments of the invention have been described forpurposes of this disclosure, it will be understood that numerous changesmay be made which will readily suggest themselves to those skilled inthe art and which are accomplished within the spirit of the inventiondisclosed and claimed.

1. A method of treating an oil or gas well that has been fractured withan aqueous gel solution to increase the flow of hydrocarbons, theaqueous gel solution having an aqueous portion and a polymer materialportion, the method comprising the steps of: contacting a fracturedformation with a soak solution, the soak solution mixing with theaqueous portion of the aqueous gel solution to increase the volatilityof the aqueous portion of the aqueous gel solution; and applying a drygas treatment to the well to evaporate the aqueous portion of theaqueous gel solution and reduce gel saturation in the fracturedformation.
 2. The method of claim 1, wherein the soak solution comprisesan alcohol having one, two or three carbon atoms.
 3. The method of claim2, wherein the soak solution comprises isopropyl alcohol.
 4. The methodof claim 1, wherein the method further comprises the step of shutting inthe soak solution for a predetermined amount of time to ensure optimummixing of the soak solution and the aqueous portion of the gel solution.5. The method of claim 1, wherein the method further comprises the stepof recovering the increased flow of hydrocarbons after applying the drygas treatment.
 6. The method of claim 1, wherein the dry gas treatmentincludes a gas selected from the group consisting of air, nitrogen,nitrogen-enriched air, single carbon atom gases, monoatomic gases,diatomic gases, subcritical drying fluids, supercritical drying fluids,flue gases, exhaust gases, combustion gases, and combinations thereof.7. The method of claim 1, wherein the single carbon atom gases can beselected from the group consisting of methane, carbon dioxide andcombinations thereof.
 8. The method of claim 1, wherein the methodfurther comprises the step of heating the dry gas before applying thedry gas treatment.
 9. The method of claim 1, wherein the soak solutioncomprises an alcohol having at least one carbon atom.